1. Field of the Invention
The invention relates generally to blowout preventers used in the oilfield industry. Specifically, the invention relates to an improved fluid union to supply fluid to an internal blowout preventer or an internal blowout preventer actuator.
2. Background Art
Well control is an important aspect of oil and gas exploration. When drilling a well, for example, in oil and gas exploration applications, safety devices must be put in place to prevent injury to personnel and damage to equipment resulting from unexpected events associated with the drilling activities.
Drilling wells in oil and gas exploration involves penetrating a variety of subsurface geologic structures, or “layers.” Occasionally, a wellbore will penetrate a layer having a formation pressure substantially higher than the pressure maintained in the wellbore. When this occurs, the well is said to have “taken a kick.” The pressure increase associated with the kick is generally produced by an influx of formation fluids (which may be a liquid, a gas, or a combination thereof) into the wellbore, The relatively high pressure kick tends to propagate from a point of entry in the wellbore to uphole (from a high pressure region to a low pressure region). If the kick is allowed to reach the surface, drilling fluid, well tools, and other drilling structures may be blown out of the wellbore. These “blowouts” often result in catastrophic destruction of the drilling equipment (including, for example, the drilling rig) and substantial injury or death of rig personnel.
Because of the risk of blowouts, blowout preventers (“BOP”) are typically installed at the surface or on the sea floor in deep water drilling arrangements to effectively seal a wellbore until active measures may be taken to control the kick. Blowout preventers may be activated so that kicks may be adequately controlled and circulated out of the system. Just as a kick will propagate up the well, it may also enter the drill string and propagate through the inside of the drill string. To control a kick inside the drill string, a drill string internal blowout preventer (“IBOP”), sometimes called a “kelly valve” or a “kelly cock,” is used to seal off the drill string until measures can be taken to control the kick.
An IBOP may be formed from a variety of different types of valves, but a ball valve configuration, as shown in FIG. 1A, is the most standard type. Ball valve type IBOPs typically include a valve ball 101 that is located between two seats 103 and 105 in the middle of a passage. The valve ball 101 has a through hole, and may be rotated between two positions: an “open” position and a “closed” position. In the open position, the through hole of the valve ball will align with the passage of the pipe or drill string (as shown), allowing undisrupted fluid flow. In the closed position, the through hole of the valve ball is misaligned with the passage of the pipe or drill string, disrupting fluid flow. In the closed position, the valve ball is able to isolate a kick inside the drill string by containing the upcoming pressure. The valve ball is rotated between the open and closed positions by a rotation device 107 on the side of the IBOP. For reasons of speed and location of the IBOP, the rotation device 107 is typically controlled by an IBOP actuator, as shown in FIG. 1B.
Because an IBOP and its actuator are connected in line with the drill string, they will rotate with the drill string during drilling operations. The IBOP actuator typically is hydraulically or pneumatically powered. A fluid source, such as a pressurized cylinder of liquid or gas, is used to power the IBOP actuator. The fluid source, however, is usually stationary and does not rotate with the IBOP, IBOP actuator, or the drill string. A problem is then presented to supply fluid from the stationary fluid source environment to the rotating IBOP actuator environment. In most applications, drilling is often stopped before actuation of the IBOP, but, for safety reasons, the IBOP and its actuator must be connected to its fluid source at all times and be capable and ready to operate indeterminate of the drill string's rotation.
As shown in FIG. 2A, one prior art IBOP actuator, disclosed in U.S. Pat. No. 4,456,217 issued to Windegeart et al. and incorporated herein by reference, includes a fluid union 270 with a rotating section 274 and a non-rotating section 272 to overcome this problem. A fluid source is routed to the non-rotating section 272 of the fluid union 270 using hydraulic fluid supply lines 214 and 216, in which the non-rotating section 272 is coupled to the rotating section 274 of the fluid union 270 through various seals 290, bearings 280, and passageways 260 and 262 to allow flow of the fluid source from the non-rotating section 272 to the rotating section 274. The rotating section 274 of the fluid union 270 then supplies the fluid source to an actuator 230 to open and close an IBOP to control the flow through a drill string.
An issue with this type of prior art fluid union is that the seals between rotating sections require frequent replacement due to wear. For example, the seals 290 within the fluid union 270 are in constant contact with both the rotating section 274 and the non-rotating section 272 of the fluid union 270, causing the seals 290 to rub against sealing surfaces rotating at high speeds. This contact and rubbing generates heat and makes the seals susceptible to increased wear and degradation, which significantly reduces the service life of the seals. With the addition of contaminates from corrosive drilling fluids, a salt-water environment, extreme ambient temperatures, and heavy vibration, seals and bearings must be replaced with high frequency to ensure reliability and function of the fluid union to actuate the IBOP.
As shown in FIG. 2B, another type of prior art fluid union is disclosed in U.S. Pat. No. 4,700,924 issued to Nelson et al. and incorporated herein by reference. The fluid union includes a rotating section 203 and a non-rotating section 201. The rotating section 203 contains an actuator 231 to open and close an IBOP 241. Deformable sealing rings 205 and 207 are disposed within the non-rotatable member 201 and hydraulic fluid supply lines 209 and 211 supply a fluid source to the non-rotating section 201. When a pressurized fluid source is supplied to the non-rotating section 201 through the supply lines 209 and 211, the sealing rings 205 and 207 move from a relaxed state to an excited state. In the excited state, the deformable sealing rings 205 and 207 form a seal against the rotatable member 203. This allows the pressurized fluid source from the supply lines 209 and 211 to flow through sealed passages from the non-rotating member 201 into the rotating member 203.
One potential issue of this type of prior art fluid union is that the deformable sealing rings must radially contract when sealing against the rotating section of the fluid union. With multiple sequences of contracting and expanding of the sealing rings between their excited and relaxed states, the sealing rings may then experience wear, cracks, or even permanent deformation, limiting the ability of the sealing rings to provide a seal.
Further, another issue with prior art fluid unions in general is that they are not readily accessible when maintenance is required. The fluid unions are typically complete circular designs which fully encompass the drill string. The design requires the fluid union to slide over an end of the drill string for installation or repair. Depending on the complexity of the fluid union and actuator design, many valuable hours may be lost for repairs and maintenance because of the inaccessibility of the fluid union.